The present disclosure relates to drilling wellbores in subterranean formations and, more particularly, to systems and methods of balancing weight and hydraulic energy distribution between individual downhole cutting tools.
Wellbores are formed in subterranean formations for various purposes including, for example, the extraction of oil and gas and the extraction of geothermal heat. Such wellbores are typically formed using one or more drill bits, such as fixed-cutter bits (i.e., “drag” bits), rolling-cutter bits (i.e., “rock” bits), diamond-impregnated bits, and hybrid bits, which may include, for example, both fixed cutters and rolling cutters. The drill bit is coupled either directly or indirectly to an end of a drill string or work string, which encompasses a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface. Various tools and components, including the drill bit, are often arranged or otherwise coupled at the distal end of the drill string at the bottom of the wellbore. This assembly of tools and components is commonly referred to as a “bottom hole assembly” (BHA).
In order to form the wellbore, the drill bit is rotated and its associated cutters or abrasive structures cut, crush, shear, and/or abrade away the formation materials, thereby facilitating the advancement of the drill bit into the subterranean formation. In some cases, the drill bit is rotated within the wellbore by rotating the drill string from the surface while a fluid, such as drilling fluid, is pumped from the surface to the drill bit. The drilling fluid exits the drill string at the drill bit via one or more nozzles arranged therein and may serve to cool the drill bit and flush drilling particulates back to the surface via the annulus defined between the drill string and the exposed surface of the wellbore. In other cases, however, the drill bit may be rotated by coupling the drill bit to a downhole motor (e.g., mud motor) also coupled to the drill string and disposed relatively proximate to the drill bit. The drilling fluid pumped from the surface may power the downhole motor to rotate the drill bit and subsequently exit out of the drill bit nozzles and circulate back up to the surface via the annulus.
To enlarge the diameter of the wellbore, a “reamer” device (also referred to as a “hole opening device” or a “hole opener”) may be used in conjunction with the drill bit as part of the BHA. The reamer is typically axially-offset and uphole from the drill bit along the length of the BHA. In operation, the drill bit operates as a pilot bit to form a pilot bore in the subterranean formation, and the reamer follows the drill bit through the pilot bore to enlarge the diameter of the wellbore as the BHA advances into the formation.
As the wellbore is drilled, axial force or weight is applied to the drill bit and the reamer from the surface via the drill string which causes the cutting tools to advance into the formation. This force is generally referred to as the “weight-on-bit” (WOB) and the “weight-on-reamer” (WOR). Efficient drilling with both the bit and the reamer can significantly affect performance and rate of penetration (ROP) into the formation. However, managing the WOB and the WOR when they are simultaneously used can be very difficult. There may be several scenarios that can impede drilling efficiency, thereby achieving not only low ROP but also premature wear on the downhole tools. For instance, a wellbore may extend through different formations or layers of geological material, and each formation may exhibit different physical properties. Some formations may be relatively soft and are easily drilled through, while others are relatively hard and difficult to drill through. As the wellbore advances through a relatively hard formation and into an underlying softer formation, the drill bit will quickly remove material from the softer formation while the reamer continues to more slowly ream out the wellbore in the harder formation. Consequently, the ratio between WOB and WOR may become undesirably and unevenly distributed between the reamer and the drill bit.
An imbalanced weight distribution between the reamer and the drill bit can result in imbalanced cuttings generation at each cutting tool, which can result in bit balling as the inefficiently flushed cuttings will tend to agglomerate about the cutting tools. During drilling operations, as briefly mentioned above, cuttings are flushed away from the cutting tools using the drilling fluid injected into the wellbore from the surface and eventually ejected out of each cutting tool via one or more nozzles defined therein. Since the nozzle sizes in each of the drill bit and reamer are selected prior to tripping into the wellbore, the hydraulic flowrate diverted through the reamer and the drill bit, and thus the hydraulic energy applied thereto, are also fixed.
The hydraulic energy expended at each cutting tool is mainly based on the pressure drop across the nozzles at the drill bit and the reamer and the pressure balance between these cutting tools since these tools are arranged in series along the BHA. Managing the hydraulic flowrate of drilling fluid through the reamer and the drill bit when they are used simultaneously can be fairly difficult. However, when efficiently managed, drilling efficiency increases, thereby increasing rate of penetration into the subterranean formation.